The present invention relates to well treatment fluids and methods utilizing nano-particles and, in certain embodiments, to well cement compositions and methods utilizing nano-clay.
In general, well treatments include a wide variety of methods that may be performed in oil, gas, geothermal and/or water wells, such as drilling, completion and workover methods. The drilling, completion and workover methods may include, but are not limited to, drilling, cementing, spacers, and lost circulation control methods. Many of these well treatments are designed to enhance and/or facilitate the recovery of desirable fluids (e.g., hydrocarbons) from a subterranean well.
In cementing methods, such as well construction and remedial cementing, well cement compositions are commonly utilized. For example, in subterranean well construction, a pipe string (e.g., casing and liners) may be run into a well bore and cemented in place using a cement composition. The process of cementing the pipe string in place is commonly referred to as “primary cementing.” In a typical primary cementing method, a cement composition may be pumped into an annulus between the walls of the well bore and the exterior surface of the pipe string disposed therein. The cement composition sets in the annular space, thereby forming an annular sheath of hardened, substantially impermeable cement that supports and positions the pipe string in the well bore and bonds the exterior surface of the pipe string to the subterranean formation. Among other things, the annular sheath of set cement surrounding the pipe string functions to prevent the migration of fluids in the annulus, as well as protecting the pipe string from corrosion. Cement compositions also may be used in remedial cementing methods, such as squeeze cementing, repairing casing strings and the placement of cement plugs. In some instances, cement compositions may be used to change the direction of the well bore, for example, by drilling a pilot hole in a hardened mass of cement, commonly referred to as a “kickoff plug,” placed in the well bore.
In operation, the annular sheath of cement formed between the well bore and the pipe string in primary cementing may suffer structural failure due to pipe movements which cause shear stresses to be exerted on the set cement. Such stress conditions are commonly the result of relatively high fluid pressures and/or temperatures inside the cemented pipe string during testing, perforating, fluid injection or fluid production. For example, such stress may occur in wells subjected to steam recovery or production of hot formation fluids from high-temperature formations. The high-internal pipe pressure and/or temperature can result in the expansion of the pipe string, both radially and longitudinally, which places stresses on the cement sheath causing the cement bond between the exterior surfaces of the pipe or the well bore walls, or both, to fail and thus allow leakage of formation fluids and so forth. Accordingly, it may be desirable for the cement composition utilized for cementing pipe strings in the well bores to develop high strength after setting and to have sufficient resiliency (e.g., elasticity and ductility) to resist loss of the cement bond between the exterior surfaces of the pipe or the well bore walls, or both. Also, it may be desirable for the cement composition to be able to resist cracking and/or shattering that may result from other forces on the cement sheath. For example, it may be desirable for the cement sheath to include structural characteristics that protect its structural integrity from forces associated with formation shifting, overburden pressure, subsidence, tectonic creep, pipe movements, impacts and shocks subsequently generated by drilling and other well operations.
Another problem that may be encountered in well cementing methods is the undesired gas migration from the subterranean formation into and through the cement composition. Problems with gas migration may be encountered during setting of the cement composition as it transitions from a hydraulic fluid to a solid mass. Gas migration may cause undesired flow channels to form in the cement composition that may remain in the cement composition after it has set into a hardened mass, potentially resulting in loss of zonal isolation.
Yet another problem that may be encountered in well cementing methods is associated with exposure to corrosive fluids. Examples of corrosive environments include exposure to acidic conditions either caused by actual placement of acid solutions for well treatment or in the presence of carbon dioxide (CO2). Carbon dioxide has been used for enhanced recovery methods by injecting CO2 into a permeable reservoir in order to displace oil and gas towards a producing well. Carbon dioxide sequestration activities involve placing CO2 into a reservoir for permanent storage. Upon exposure to water, the CO2 may yield carbonic acid. In addition, the carbon dioxide may also convert exposed cement surfaces to calcium carbonate, a process commonly referred to as carbonation. Calcium carbonate being acid soluble may then slowly be dissolved by the carbonic acid. Dissolution of the calcium carbonate by the carbonic acid may be more severe in a cement sheath with a higher permeability due to more flow paths for the carbonic acid into the cement sheath. To counteract problems associated with exposure to corrosive fluids, additives may often be added to a cement composition to reduce the permeability of the cement sheath. For example, latex additives have been added to reduce permeability. Reducing the water content by optimized particle packing also may reduce the permeability of the cement sheath. Reduction of the permeability of the cement sheath generally may reduce flow paths for the acid, thus reducing the exposure of the cement sheath to potentially damaging acid.